It’s a great day for the Federal Energy Regulatory Commission (FERC) and supporters of demand response. Today, the United States Supreme Court issued its decision in FEDERAL ENERGY REGULATORY COMMISSION v. ELECTRIC POWER SUPPLY ASSOCIATION ET AL., upholding the FERC’s authority to regulate wholesale demand response as well as FERCs method of compensating demand response participants. In the 6-2 decision, the Supreme Court ruled:

  • The practices at issue directly affect wholesale rates.
  • The Federal Power Act (FPA) provides FERC with the authority to regulate the wholesale electric market.
  • FERC has not regulated retail sales.
  • FERC’s method of compensating demand response participants at locational marginal pricing (LMP) is not arbitrary and capricious.
  • A contrary view would conflict with the FPA’s core purposes by preventing the use of a tool (demand response) that will curb prices and enhance reliability in the wholesale electricity market.

Before the chill of last winter’s polar vortex, many in the industry may not have even heard the term uplift payments. If you are still wondering exactly how it works, the Federal Energy Regulatory Commission (“FERC”) has a docket and workshop for you (Docket No. AD14-14-000). At this docket you will find an educational staff report on uplift payments in RTOs/ISOs. On Monday, September 8, 2014, FERC will hold a workshop to explore the technical, operational and market issues that give rise to uplift payments and the levels of transparency associated with uplift payments. The daylong informative workshop will begin at 8:45 a.m. and conclude at 5:15 p.m.

Panel 1 will address the basic issue of “What is uplift?” and explore issues that give rise to uplift payments as well as:

  • Drivers of uplift payments in RTOs/ISOs
  • Uplift payments that have been highly concentrated and persistent on a geographic or resource basis
  • Technical, operational and market issues driving uplift payments
  • The relationship between uplift payments and unit flexibility

Panel 2 will explore the impact of uplift on market participants.

Panel 3 will explore the adequacy of and the potential to enhance uplift transparency and recent market design changes that may address some of the causes of uplift.

Panel 4 will explore broader price formation issues and discuss next steps.

This agenda provides further details. As expected, the event will be held at the Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426. This workshop is free of charge and open to the public.

In a recent order, the Massachusetts Department of Public Utilities (“Department” or “DPU”) stated that time varying rates are an essential component of grid modernization. As a result, the design of basic service must change to incorporate time of use (“TOU”) rates for all customers, including residential customers. The Department noted that in 2013, the average wholesale market price of electricity over the course of the year was $56 per megawatt-hour (“MWh”), but the peak wholesale price in the summer reached nearly $870 per MWh and in winter nearly $1,300 per MWh. However, despite the volatility in the wholesale market, basic service customers’ rates did not reflect the time varying nature of electricity supply costs. The Department sees this as a problem. (Warning: DPU should take a short flight down to PJM land where customers’ exposure to last winter’s price spikes is still being discussed.) Nevertheless, DPU is concerned because under the current basic service structure in Massachusetts, rates do not reflect the time varying nature of electricity supply costs. Additionally, customers who are able to shift more of their electric usage to off-peak/lower wholesale cost hours subsidize customers who use more electricity during hours with higher wholesale electricity prices.

The Time Varying Rates Order describes a policy framework that will require electric distribution companies to offer two basic service TOU options:

  1. A default product with time of use pricing that includes a critical peak pricing (“CPP”) component. Under this TOU pricing structure, the retail electricity price will be higher during certain hours of the week when customers typically use more electricity and wholesale energy prices rise (e.g., the “on-peak” hours of noon to 8:00 p.m. each weekday) than during the remaining hours of the week when electricity usage and wholesale prices are typically lower (i.e., the “off-peak” hours).
  2. A flat rate with a peak time rebate (“PTR”) option. With a PTR, customers will receive a rebate if they lower their electricity use relative to a pre-established baseline during times when wholesale hourly energy prices are highest. Thus, under PTR, customers will have an incentive to lower their electricity usage when it is most critical to do so, but even those who ignore the incentive will be insulated against higher peak prices because they will pay one price for all electricity consumption.

The Department anticipates that the on-peak rate will be higher and the off-peak rate lower than a flat-rate product. Thus, customers who respond to price signals by reducing on-peak energy consumption will pay less than they would under a flat rate.

Written comments regarding this policy framework may not exceed 25 pages and must be submitted no later than the close of business (5:00 p.m.) on July 3, 2014.

Later this year, NIST expects to release a draft of the Framework and Roadmap for Smart Grid Interoperability Standards (“Framework”) document for a formal 60-day public comment period and the final version of the document is planned for publication in the first half of 2014. However, those attending the SGIP Inaugural Meeting received an advanced look at the new Framework.

NIST says the smart grid will ultimately require hundreds of standards. To prioritize its work, NIST chose to focus on seven key functionalities plus cybersecurity and network communications. Together, they create nine priority areas:

  • Demand response and consumer energy efficiency: Provide mechanisms and incentives for utilities, business, industrial and residential customers to modify energy use during times of peak demand or when power reliability is at risk. Demand response is necessary for optimizing the balance of power supply and demand.
  • Wide-area situational awareness: Utilizes monitoring and display of power-system components and performance across interconnections and over large geographic areas in near real-time. The goals of situational awareness are to understand and ultimately optimize the management of power-network components, behavior and performance, as well as to anticipate, prevent, or respond to problems before disruptions arise. 
  • Distributed Energy Resources (DER): Covers generation and/or electric storage systems that are interconnected with distribution systems, including devices that reside on a customer premise, “behind the meter.” DER systems utilize a wide range of generation and storage technologies such as renewable energy, combined heat and power generators (CHP), fixed battery storage and electric vehicles with bi-directional chargers. 
  • Energy Storage: Means of storing energy, directly or indirectly. The most common bulk energy storage technology used today is pumped hydroelectric storage technology. New storage capabilities — especially for distributed storage — would benefit the entire grid, from generation to end use.
  • Electric transportation: Refers primarily to enabling large-scale integration of plug-in electric vehicles (PEVs). Electric transportation could significantly reduce U.S. dependence on foreign oil, increase use of renewable sources of energy, provide electric energy storage to ameliorate peak-load demands, and dramatically reduce the nation’s carbon footprint. 
  • Network communications: Refers to a variety of public and private communication networks, both wired and wireless, that will be used for smart grid domains and subdomains. An interface is a point where two systems need to exchange data with each other. Effective communication and coordination occurs when each of the systems understand and can respond to the data provided by the other system, even if the internal workings of the system are quite different.
  • Advanced metering infrastructure (AMI): Provides near real-time monitoring of power usage. AMI consists of the communications hardware and software, and the associated system and data management software, that together create a two-way network between advanced meters and utility business systems, enabling collection and distribution of information to customers and other parties, such as the competitive retail supplier or the utility itself. 
  • Distribution grid management: Focuses on maximizing performance of feeders, transformers and other components of networked distribution systems and integrating them with transmission systems and customer operations. As smart grid capabilities such as AMI and demand response are developed, and as large numbers of distributed energy resources and PEVs are deployed, the automation of distribution systems becomes increasingly more important to the efficient and reliable operation of the overall power system.
  • Cybersecurity: Encompasses measures to ensure the confidentiality, integrity and availability of the electronic information communication systems and the control systems necessary for the management, operation and protection of the smart grid’s energy, information technology and telecommunications infrastructures.

Given the importance and magnitude of the smart grid, at the most basic level just about everyone you know is a stakeholder. According to NIST, the stakeholder groups who may find Framework 3.0 most useful include:

  • Utilities and suppliers concerned with how best to understand and implement the smart grid (especially Chapters  4, 5 and 6);
  • Testing laboratories and certification organizations (especially Chapter 7);
  • Academia (especially Section 5.1 and Chapter 8); and
  • Regulators (especially Chapters 1, 4, and 6, and also Section 3.5).

Demand response, energy efficiency and renewable energy all play a role in the development of the smart grid. Given the services they offer, I thought the Department of Energy’s Office of Energy Efficiency and Renewable Energy (EERE) deserves a shout out. I suspect many are not aware of the free technical expertise and information the office provides. Created to facilitate the development of energy efficiency and renewable energy technologies and market-based solutions, EERE has a team of talented engineers and others who work to develop and deliver market-driven solutions for energy-saving homes, buildings, manufacturing, sustainable transportation and renewable electricity generation. The Technical Assistance Program (TAP) will benefit regulators, utilities, state and local government and even school districts. One-on-one support is available in addition to an informative webinar series. The program covers a range of topics including financing solutions. Here are a few upcoming webinars:

Commercial Building Energy Data Access: A Success Story
Tuesday, August 6, 2013; 3–4:30 p.m. EDT
Register to attend
This webinar will present the underlying barriers affecting access to building energy data and the solutions currently underway across the country. The webinar will also feature the successful collaboration between building owners, utilities, regulators and policymakers in Philadelphia, and new resources that state and local leaders can use to replicate this model in their communities, including SEE Action’s Utility Regulator’s Guide to Data Access for Commercial Building Energy Performance Benchmarking. State and local government leaders, state utility regulators, building managers, energy consultants and other key stakeholders are encouraged to attend.

TAP Webinar: Emerging Technologies
Thursday, August 15, 2013; 2–3:30 p.m. EDT
Register to attend
This webinar on Emerging Technologies and Energy Efficiency will cover how states can use new technologies to reduce energy consumption and carbon emissions. This presentation will highlight new technologies and approaches to auditing, building retrofitting, lighting, heating, cooling, retro-commissioning and deep energy retrofits that can assist state and local programs in reaching energy sustainability. Attendees will have an opportunity to ask questions of the internationally-known Jesse Dean of NREL and other presenters, offering local and national experience.

Utilities service territories are unique in many ways, including geography and culture. Despite the differences, there are benefits gained from studying the experiences of peers. Voices of Experience|Insights on Smart Grid Customer Engagement provides practical advice from utilities that have implemented smart grid projects to educate and engage their customers. It’s an effort to capture the industry’s knowledge regarding customer engagement related to smart grid deployment. While the guide may lean towards advanced metering infrastructure, the principals and insights apply to a much broader perspective, including engaging customers for dynamic pricing programs, demand response programs, distribution automation and other technology, such as home area network (HAN) devices. The guide is practical, often providing links to detailed examples actually implemented by utilities. As a contributor, I am partial: The guide is a must read for utilities involved in smart grid deployment.

With smart grid events being offered almost daily, unless your day job is to attend seminars, a vetting of the agenda and presenters is critical. The Association for Demand Response & Smart Grid, now simply known as ADS, is celebrating its 10th anniversary and lived up to expectations this week with the commencement of its signature event, The National Town Meeting on Demand Response and Smart Grid. With knowledgeable and experienced presenters from the White House to the California Public Utility Commission, the dialog at Wednesday’s meeting highlighted policy, pricing, innovation and barriers. Sitting in the audience, the conversation among attendees was as enlightening as the thought-provoking discussions from the panelists.

During a break, I had a great conversation with Jamison (Jay) Shaver from GE’s Digital Energy business. From light bulbs and appliances for residential customers to a suite of products to help utilities develop an intelligent and resilient distribution grid, GE is smart-grid-poised industry wide. As Jay discussed with me the five core components of the modern grid, he stressed that many of the supporting systems and platforms used by utilities can now be seamlessly integrated, providing better access to outage information across functional areas such as customer service, dispatch and engineering. Having a dashboard ready with various data points should improve the restoration process. According to Digital Energy, here are the five core grid modernization components:

  1. Smart meters and an advanced metering infrastructure (AMI),
  2. Geographic information system (GIS),
  3. Outage management system (OMS),
  4. Distributed management system (DMS) and
  5. Distribution automation (DA) capabilities.

Jay says these core elements work cohesively to help prevent outages. Typically morbid, I learned about the concept of a smart meter “last gasp”: As the power goes out, smart meters transmit important data to the utility, notifying them of the outage and other diagnostics. Such vital information improves restoration efforts. Knowledge is power.

I am looking forward to the National Town Meeting on Demand Response & Smart Grid July 9-11, 2013. It is one event I enjoy attending as it typically provides a wealth of information about these important topics. I am pleased to offer readers a glimpse into the National Town Meeting as I recently had the opportunity to ask Dan Delurey, president of the Association for Demand Response and Smart Grid (ADS), a few questions regarding the upcoming meeting.  

Evers: Dan, what would you describe as one of the foremost issues facing DR and how will it be addressed at the NTM?

Delurey: At the Town Meeting we will discuss a whole range of issues, challenges, and opportunities facing DR and smart grid. One of the key topics is the issue of time-based pricing and how to move that forward in the states. Time-based pricing is critical for making people aware that electricity does not cost the same to produce and deliver at all times, and for giving them the price signals that will encourage them to participate in DR programs. Many smart meters (which are necessary for such pricing because they measure on intervals) are now installed, and a very large amount of research shows that many customers will accept time-based rates. Now we need action by state utility commissions and utilities. At the Town Meeting we will discuss some new data on time-based pricing, and talk about how policy can be moved forward in a way that all stakeholders will accept.  

Another important issue we will be covering at the Town Meeting is including DR in new business and policy areas, such as building codes and design. Technologies such as building energy management systems (BEMs), programmable thermostats, and smart lighting and appliances have opened up a great opportunity for DR to reduce building energy usage. However, to really encourage this growth, these kinds of technologies must be included in the buildings themselves, which is where building codes and design standards come in.

Evers: This is all really great stuff. Will there be any information provided regarding the smart grid?

Delurey: On the smart grid side of things, we have an entire session devoted to microgrids and another one devoted to improving flexibility and resilience. We will also present some case studies on distribution automation and management. All of these may not get as much attention as smart meters, smart buildings and smart pricing, but they are very important in optimizing the overall electricity system.

Evers: A lot of small cities and towns are hurting financially and like most businesses, energy is most likely in the top five of their budget spend. How can they benefit from DR and the conference?

Delurey: Institutional buildings, such as municipal government buildings, are prime candidates for DR programs. If they have not done so already, local governments should talk to their utility or to a DR company about joining a DR program. DR usually provides an additional revenue stream to the owners of buildings on top of what they get from their energy savings. That would help them from a budgetary standpoint.    

A new area where local governments can engage in DR is dynamic street lighting. Almost all local governments spend money on street and public area lighting.  With new technology that allows lighting to be automatically and dynamically controlled, local governments can better optimize their street lighting and save money. For example, they can program these lights to dim when electricity costs more (if combined with time-based pricing), or they can even brighten the lights in certain areas or at certain times to deter crime (but save money by not having to brighten all of the lights). This is an exciting new area of the smart grid, right at the intersection of DR and energy efficiency, and we will have a presentation at the Town Meeting about it.

Evers: Last year you gave out your first Griddie Awards. How was it received? Care to give us a teaser on some of this year’s nominees? Any new faces or organizations?

Delurey: Last year we got a lot of feedback that the Griddie Awards were a great new addition to the Town Meeting. The Griddie Awards recognize the best marketing and communications efforts for smart grid programs and technologies. Attendees at the Town Meeting got to vote in real-time on which finalists they wanted to win, so it was another way to encourage participation and involvement in the event by all attendees. This year we’ve gotten a lot of great submissions from all over the country, which can be seen on our website. The large number of submissions shows that there are a lot of marketing and educational efforts going on to make customers aware of the DR and smart grid programs and technologies available to them, and how they can benefit from these. I hope you’ll come to the Town Meeting to find out who the winners are!

Evers: Thanks Dan.

If you are interested in attending the National Town Meeting, it’s not too late to register. I’ll see you there!

The North American Electric Reliability Corporation’s (NERC) 2012 Summer Reliability Assessment finds most of North America has sufficient resources available to meet summer peak demands, however, planning reserve margins in the Electric Reliability Council of Texas (ERCOT) assessment area are projected to be below the NERC Reference Margin Level, the threshold by which resource adequacy is measured. In California, reserves are projected to be tight but manageable through the summer months.

With continued growth in peak demand and only a small amount of new generation coming online, resource adequacy levels in ERCOT have fallen below targets,” said John Moura, manager of Reliability Assessment at NERC. “If ERCOT experiences stressed system conditions or record-breaking electricity demand due to extreme and prolonged high temperatures, system operators will most likely rely on demand response and emergency operating procedures, which may include initiating rotating outages to maintain the reliability of the interconnection.

Texas is no stranger to rotating outages. Shortly before Super Bowl XLV, brownouts occurred when extreme cold weather hit the Southwest the first week of February 2011. The Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation released a staff report making recommendations to help prevent a recurrence of rolling blackouts and natural gas curtailments. Hopefully the lessons learned can help this situation. 

Despite the concerns in Texas and California, according to Mark Lauby, vice president and director of Reliability Assessment and Performance Analysis, NERC has reviewed the operating procedures and preparations in the assessment areas, and in most areas they appear to be sufficient to meet these challenges. Since summer 2011, capacity resources have grown across North America by approximately 12,310 megawatts, most notably within the SERC Reliability Corporation and the Northeast Power Coordinating Council areas. Compared to the 2011 projections, NERC-wide total peak demand forecast is 3,700 MW lower. The largest increase in peak demand is expected in ERCOT, where a 1.7 percent increase is projected.

I said 2011 was the year of the opt-out, but based on a couple of recent Commission orders, 2011 may have been a preamble. Texas, a state known for a robust competitive electric market and with millions of smart meters already installed, has decided to conduct an investigation to formally address the opt-out issue. When a decision has been made, will let you know. 

In the meantime, I thought this well-written March 2011 Smart Grid Technical Advisory Project authored by the Lawrence Berkeley National Laboratory would shed some light on the importance of smart meters to the smart grid. The slide on page 16 presents some great questions for regulators to consider as they address the opt-out issue:

  • Should advanced meters be mandatory or voluntary?
  • How do you craft a potential opt-out option that does not undermine either the advanced metering business case or utility system smart grid operation?
  • How should the cost of any opt-out provision be allocated?
  • Should costs be allocated to those that opt-out? or
  • Should costs be “socialized” and distributed across all customers?
  • What implications does a metering opt-out provision have for rate, demand response, electric vehicle and other smart grid initiatives?

Bonus: For those who read the full report, you will learn that you can be advanced, but not smart.